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Alberta gas gets jolt of hope Canada’s two leading regulators add 12 percent to Alberta’s conventional natural reserves; others point to galloping challenges over next decade Gary Park Petroleum News Calgary Correspondent
Canada’s two leading energy regulators lifted the spirits of those who see a shrinking outlook for natural gas in Alberta, the source of 80 percent of Canada’s output, but other forecasters are painting a darker picture.
In a joint study, the National Energy Board and Alberta Energy and Utilities Board raised the estimate for marketable conventional supplies in the province to a “most realistic” 223 trillion cubic feet, 12 percent higher than the Alberta agency’s 1992 estimate and 7 percent above a 1994 figure by the NEB.
The study said the ultimate potential — which covers gas already produced plus the remaining resource — could even rise to 253 tcf, more than double the 122 tcf extracted to date.
The findings indicate that Alberta could be pumping gas for longer than previously thought, said an official at the Alberta board.
Canada’s ability to “remain a key supplier of natural gas (it currently accounts for about 25 percent of North American production) will depend on the size and quality of its resource base,” the report said. Reserves growth not matching production Despite record levels of drilling, reserves growth “has been unable to match production and Alberta appears to have reached, or at least is very near, its peak capacity. Consequently, there is significant interest in Alberta’s ultimate potential for marketable conventional natural gas.”
The two regulators said a “large number of wells have been drilled in development areas to maintain contract rates and were not for exploratory purposes.”
But the surge in gas prices has “resulted in the exploration for and development of many new low-productivity pools that were previously beyond economic reach.”
Greg Stringham, a vice president with the Canadian Association of Petroleum Producers, said the increase in projections is “quite enlightening” for the Western Canada Sedimentary Basin at a time when the industry has questioned whether the region has been starting to flatten out.
Now, he said, it is a matter of finding the gas and bringing it on stream. Geology now better understood The study said the primary reason for the increased potential is a “better understanding of the geology of (Alberta) gained as a result of the increased drilling since 1992.”
The findings were based on data from 320,000 wells drilled by the end of 2004, which was double the well count at the end of 1991.
But the estimate does not take into account unconventional gas, which is expected to account for about one-fifth, or 3,000 of all the gas wells drilled in Canada this year.
The report noted that Alberta’s remaining gas potential will need to be supplemented from unconventional supplies “in order to meet Canadian domestic and export demands.
“Extraction of both types of gas resources will contribute to a healthy and vibrant oil and gas industry in Alberta for many years to come.”
The statistics were released during a Canadian Energy Research Institute gas conference in Calgary.
It also followed an institute study that said Western Canadian production has “reached a plateau and will likely decline significantly despite continuing to set a new drilling activity record in each of the past few years.”
The jointly government-industry agency concluded the prices needed for development and delivery suggest Western Canada’s production “could be maintained for a decade or so, but would decline inexorably after 2015.”
It said mergers and acquisitions have reduced the ranks of Canadian independents and asset swaps and sales have “created a sector focused almost exclusively on exploitation and drilling development wells,” leaving exploration at only 15 percent of total drilling.”
Without a “consistently higher level of exploration, industry is finding it difficult to replace production and all but impossible to grow supply,” CERI said.
Average new pool discoveries have shrunk since the early 1990s from 1 million cubic feet per day of initial production to 350,000 cubic feet per day. Drilling focus shallow In other observations CERI said:
• Coalbed methane, despite different reservoir conditions and operative practices, should not be considered as “inherently any different from conventional shallow gas.” The institute is currently working on a study of coalbed methane economics in Western Canada.
• Western Canada’s rig fleet has mushroomed to about 730, but the fleet capabilities are skewed towards shallow drilling, which accounts for 75 percent of the wells drilled in the southern half of the basin. As a result, more wells are needed just to sustain production.
• Only 10 percent of the rigs are capable of drilling deeper than 11,500 feet, when more of those wells are needed to unlock significantly larger reserves and higher initial production rates.
• Reserves are being drawn down at an ever faster rate, with improvements in completion technologies and operational efficiencies contributing to a 25-30 percent drop in new gas wells in their first year of production.
• The “production replacement treadmill,” based on the heavy reliance on shallow depth gas development, means the upstream sector will barely replace production this year because the 17,500 wells will average not much more than 3,280 feet. For the past several years the industry has had to replace about 3 billion cubic feet per day of production before it could even contemplate supply growth. F&D cost has more than doubled Calgary-based Ziff Energy Group reported earlier in March that the finding and development costs in the Western Canada basin more than doubled from 1999 to 2003 to 93 cents per thousand cubic feet equivalent, while Forward Energy Group said the 2003 F&D cost was close to triple the 1990-1996 average.
Forward President Dave Flint told the CERI conference that capital spending on gas in the Western Canada basin since 2000 has equaled about 75 percent of the gas-generated cash flow.
To sustain the investment return at the rate costs are rising will require gas prices of about $11.60 per thousand cubic feet by 2015, Flint predicted, while maintaining production would require more than 30,000 wells a year — an unlikely prospect, he said.
Ziff Chief Executive Officer Paul Ziff also noted that the reserve life index for Canada’s top 30 producers has descended to an all-time low of 7.9 years, compared with about 10 years for top U.S. producers, although the comparisons are slightly distorted because Canada is a major net exporter, while the United States relies so heavily on imports.
However, the United States is outpacing Canada in exploiting deeper and tighter formations, which make up the bulk of its production outside of coalbed methane.
The average Canadian well is about 3,500 feet, while the United States is at about 6,000 feet, he said.
The upside for Canada, Ziff told a seminar, is that Canada is just scratching the surface of its unconventional resources and trails the United States by about 20 years in tackling tight gas plays.
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